Active magnetic ranging while drilling

ABSTRACT

A magnetic ranging system for use with a drilling assembly in a borehole in a formation, the drilling assembly including a drill string, a drill bit and a bottomhole assembly (BHA) connected to the drill bit, the BHA including a measurement-while-drilling (MWD) system, a bi-directional MWD telemetry interface, and a steerable component, may comprise at least one ranging magnetometer incorporated into the BHA. The ranging magnetometer may be configured to collect ranging measurements from behind the drill bit and the ranging magnetometer may be configured to transmit measurement data. The magnetic ranging system may include at least two ranging magnetometers, with one ranging magnetometer positioned above the MWD system and one ranging magnetometer positioned below the MWD system.

RELATED APPLICATIONS

The present application is a continuation application which claimpriority from U.S. utility application Ser. No. 17/538,930, filed Nov.30, 2021 which is itself a nonprovisional application which claimspriority to U.S. application Ser. No. 63/119,531 entitled “ActiveMagnetic Ranging Integrated with a Drilling System” and filed Nov. 30,2020, each of which is hereby incorporated by reference in its entirety.

BACKGROUND

Nonaccess ranging may be used for construction of relief wells andcomplex plug and abandonment projects where the distance and directionto a target borehole is measured without access to the target. In somedrilling contexts, rotary steerable drilling systems may be used toachieve desired rates of penetration or total depths. In traditionalsystems, magnetic ranging measurements are made with a separate runusing a wireline tool. During drilling stops, the drilling bottom holeassembly is tripped to surface, the wireline tool is deployed,measurements are made, the wireline tool is removed and a drilling BHAis tripped in to resume drilling.

Access-dependent ranging may be used for construction of complexmulti-bore geometries in which both bores are accessible from surfacedown to the point where ranging to or from is required. In traditionalsystems, the target well must have at least a portion of its drillingcompleted so that the drilling assembly may be removed and an activeranging system inserted into the target using wireline.

SUMMARY

In some embodiments, a magnetic ranging system may be provided for usewith a drilling assembly in a borehole in a formation. The drillingassembly may include a drill string, a drill bit and a bottomholeassembly (BHA) connected to the drill bit, the BHA including ameasurement-while-drilling (MWD) system, a bi-directional MWD telemetryinterface, and a steerable component. The magnetic ranging system maycomprise at least one ranging magnetometer incorporated into the BHA,the ranging magnetometer may be configured to collect rangingmeasurements from behind the drill bit, and the ranging magnetometer maybe configured to transmit measurement data.

The magnetic ranging system may include at least two rangingmagnetometers, with one ranging magnetometer positioned above the MWDsystem and one ranging magnetometer positioned below the MWD system. Themagnetic ranging system may include at least two ranging magnetometersand at least one ranging magnetometer may be integral with the MWDsystem.

The magnetic ranging system may include at least two rangingmagnetometers, with one ranging magnetometer positioned above thesteerable component and one ranging magnetometer positioned below thesteerable component. The magnetic ranging system may include at leasttwo ranging magnetometers and one ranging magnetometer may be integralwith the steerable component.

At least one ranging magnetometer may be configured to measure a fieldgradient. At least one magnetometer may be mounted in the bottom driveshaft of the steerable component. At least one ranging magnetometer maybe configured to transmit measurement data via an MWD telemetryinterface.

The magnetic ranging system further may include an injection electrodeand a return electrode above the injection electrode. The injectionelectrode may be configured to inject current into the formation. Theinjection electrode and the return electrode may both be supported onthe drill string above the ranging magnetometer. The injection electrodemay be in the bit and the return electrode may be above the bit suchthat at least one ranging magnetometer may be between the injection andreturn electrodes.

The magnetic ranging system may further include a power supply for theinjection electrode The power supply may be integral with the BHA. Aportion of the bottom hole assembly between an electrode and the rangingmagnetometer may be electrically insulated from formation and wellborefluids. An electrical connection between a power supply and theinjection electrode may comprise at least one of a wireline, a wirepassing through the drillstring, and an insulated current pathintegrated with the drillstring.

In other embodiments, a system for drilling first and second boreholesin a formation may comprise a first drilling assembly in the firstborehole and a second drilling assembly in the second borehole. Thefirst drilling assembly may include a first drill string, a first drillbit and a first bottomhole assembly (BHA) connected to the first drillbit. The first BHA may include a first measurement-while-drilling (MWD)system, a first bi-directional MWD telemetry interface, a first steeringcomponent, and a first magnetic field source comprising at least onepermanent magnet having a north-south axis perpendicular to thelongitudinal axis of the first BHA, so as to create an ellipticallypolarized magnetic field during longitudinal rotation of the first BHA.The second drilling may include a second drill string, a second drillbit and a second BHA connected to the second drill bit, the second BHAincluding a second MWD system, a second bi-directional MWD telemetryinterface, a second steering component, and at least one rangingmagnetometer incorporated into the BHA, the first ranging magnetometermay be configured to collect ranging measurements of the ellipticallypolarized magnetic field generated in the first drilling assembly, theranging measurements are collected from a location behind the seconddrill bit.

The first and second BHAs may each include at least one permanent magnethaving a north-south axis perpendicular to the longitudinal axis of saidrespective BHA and at least one ranging magnetometer incorporated intothe respective BHA. The first and second ranging magnetometers may beconfigured to collect ranging measurements from behind the first andsecond drill bit, respectively.

At least one of the first and second BHAs may include two permanentmagnets having a north-south axis perpendicular to the longitudinal axisof the first BHA, and the two permanent magnets may be above and spacedapart along the at least one BHA. The first and second BHAs each mayinclude a second permanent magnet having a north-south axisperpendicular to the longitudinal axis of said respective BHA, and eachsecond permanent magnet may be above and spaced apart along therespective BHA from the respective first permanent magnet.

In other embodiments, a method for drilling first and second boreholesmay comprise a) providing a system for drilling first and secondboreholes in a formation, the system comprising: a first drillingassembly in the first borehole, the first drilling assembly including afirst drill string, a first drill bit and a first bottom hole assembly(BHA) connected to the first drill bit, the first BHA including a firstmeasurement-while-drilling (MWD) system, a first bi-directional MWDtelemetry interface, a first steerable component, and a first magneticfield source; and a second drilling assembly in the second borehole, thesecond drilling assembly including a second drill string, a second drillbit and a second BHA connected to the second drill bit, the second BHAincluding a second MWD system, a second bi-directional MWD telemetryinterface, a second steerable component, and at least one rangingmagnetometer incorporated into the BHA, the first ranging magnetometerconfigured to collect ranging measurements from behind the second drillbit; b) during rotation of the first BHA, generating a magnetic fieldusing the first magnetic field source; c) using the at least one rangingmagnetometer in the first or second well to measure the magnetic fieldcreated in step b); and d) using the measurements made in step c) tosteer at least one of the first and second drilling assemblies.

The first and second drilling assemblies may both be rotating duringstep b). The magnetic field source may comprise at least one permanentmagnet having a north-south axis perpendicular to the longitudinal axisof the first BHA, so as to create an elliptically polarized magneticfield during longitudinal rotation of the first BHA. Step c) may becarried out without tripping out the first or second drillstring orrequiring wireline access to the first or second borehole.

The magnetic field source may comprise one or more permanent transversemagnets having a north-south axis perpendicular to the axis of the firstborehole so as to create an elliptically polarized alternating magneticfield during rotation of the first BHA, the ranging magnetometer mayhave at least two axes orthogonal to the axis of the second borehole,and the ranging magnetometer may include sensors mounted so as to enabledetermination of their direction with respect to the second MWD system.

The magnetic field source may comprise a current injected intoformation. The first drilling assembly may further include an electrodefor injecting current into the formation, and power may be supplied tothe electrodes via an insulated current path that may be integral withthe drillstring.

Step d) may include measuring a passive magnetic signature of aferromagnetic target and computing a distance and direction to thetarget. Step d) may include making distance and direction calculationsdownhole. The method may further include a step of communicating a bitdepth downhole from surface and used the bit depth in step d). Themethod may further include a step of communicating measurement data tothe surface and/or a step of communicating raw data to the surface. Themethod may further include repeating steps b)-d) without surfaceintervention. Step d) may include making steering decisions based onactive data alone, passive data, or a combination of active and passivedata.

The first and second drilling assemblies may each include at least twomagnetic field sources and at least one ranging magnetometer. Step b)may comprise using each magnetic field source to generate a distinctmagnetic field, and step c) may comprise using the ranging magnetometersin the first and second boreholes to measure the magnetic fields createdin step b). Step d) may include combining measurements made in step c)with averaging or data fitting techniques including wellbore surveyinformation, or with machine learning methods.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detaileddescription when read with the accompanying figures. It is emphasizedthat, in accordance with the standard practice in the industry, variousfeatures are not drawn to scale. In fact, the dimensions of the variousfeatures may be arbitrarily increased or reduced for clarity ofdiscussion.

FIGS. 1A-1C are schematic diagrams illustrating three concepts relatingto an embodiment of the present disclosure.

FIG. 2 is a schematic diagram of a system in accordance with anembodiment of the present disclosure.

FIGS. 3A and 3B are schematic diagrams of devices for use in conjunctionwith the concepts illustrated in FIG. 1 .

FIGS. 4A-4D are schematic diagrams of devices in accordance withembodiments of the present disclosure.

FIG. 5 is a schematic diagram of a device in accordance with anotherembodiment of the present disclosure.

FIG. 6 is a schematic diagram of a system in accordance with anotherembodiment of the present disclosure.

DETAILED DESCRIPTION

Active Ranging While Drilling (ARWD)

Certain embodiments include a system for active magnetic rangingwhile-drilling (ARWD). These technologies allow ranging shots to beacquired during drilling operations. In operations, the system allowscollection of active ranging shots during each cycle of the rig mudpumps, whether at connection or for dedicated ranging shots. Usingtechniques disclosed herein, ranging shots can be collected on-demand.Furthermore, the techniques disclosed herein reduce drilling risk byeliminating significant static open hole operations that would otherwisebe required while wireline tools are run.

As used herein, “above” and “behind” each mean relatively closer to thesurface as measured along the drillstring or along the borehole.

As used herein, ““measurement data” refers to all forms of dataresulting from magnetic field measurements, accelerometer measurements,and gyroscope measurements, including but not limited to raw orprocessed magnetic field data, computed vectors, ranging results andqualifiers.

Likewise, although many components many be depicted as separate, any ofthese items may be integrated together into single components as iscommon in the art. Such integration does not impact functionality.

In some embodiments, an ARWD system may include, for example, a gradientmagnetometer array (GMA), a downhole current injection (DCI) system, andan MWD controller. These components may be included on or form part ofthe Bottom Hole Assembly (BHA).

MWD Gradient Magnetometer Array

Active Magnetic Ranging may use gradient magnetometer systems to detectmagnetic fields generated when current flows along a target borehole'scasing. In some embodiments, a MWD Gradient Magnetometer Array (GMA) maybe included on or integrated into to the BHA and connected to the MWDsystem.

The GMA may include integrated control and digital signal processingelectronics and subsystems that control data acquisition from amulti-axis magnetometer array. Processed data may be provided to thehost MWD system via MWD interconnects, which may also allow forbi-directional triggering, communication and power. In some embodiments,an ARWD system design may include a second, concurrently operating GMAin the MWD system. This provides further efficiency, ranging accuracy,redundancy, and direct calculation of relative target trajectory byenabling simultaneous magnetic field measurements at two distances fromthe target wellbore casing.

Downhole Current Injection System

Active magnetic ranging uses an accumulation of injected current ontothe target borehole's casing to create a magnetic field that can bedetected by the ranging magnetometers. In some embodiments, a downholecurrent injection system may include a BHA-mounted current injectionsystem that is a self-contained unit with power generation, storage,conditioning, and injection switching. The downhole current injectionsystem may also include one or more electrical isolation devices thatprovide electrical insulation for the injection electrodes so as toensure a desired geometry for current injection to the surroundingformation while avoiding leakage back to the drilling BHA. One or moreelectrical isolation devices may be integral with the BHA or mounted onthe BHA.

MWD System Integration

The downhole current injection system may be integrated with an MWDsystem. In certain embodiments, when the MWD detects no-flow (e.g. at aconnection), an MWD survey will be triggered. In some embodiments of anARWD system, the MWD may also initiate current injection by theconnected downhole current injection system, while simultaneouslytriggering data acquisition in the GMA. Following that acquisition, theGMA may complete initial downhole processing of the acquired data usingranging algorithms and may pass the processed data to the MWD. At adesired time, such as when drilling resumes, the processed data may thenbe telemetered to surface using the host MWD system.

Downhole Generator/Injection Unit

In some embodiments, a downhole injection unit (DIU) may be separateunit from the main MWD. By way of example only, a DIU may be located60-100 ft above the main MWD system. In some embodiments, the DIU maygenerate and store injection energy during periods when drilling fluidsare circulating and may be triggered to release the stored injectionenergy when the system executes a “ranging shot” during a period of nofluid circulation. The DIU may inject High Voltage AC current intoformation via injection electrodes. An exemplary injection may have thefollowing parameters: 300 VAC, 2-10 Hz, 5-10 A, and may last 10-30seconds per shot. A DIU may be installed in fixed collar with fixedlower injection electrode.

Lower Injection Electrode and Gaps

In some embodiments, a ARWD system may include a lower current injectionsub positioned between a lower wired pipe gap sub and a gap sub, withthe wired pipe gap sub above the injection sub. The subs use standardwired pipe connections, thereby allowing additional gap subs to be addedif required to increase insulation/reduce current accumulation. Thelower injection sub may include a stabilizer to reduce gap shorting andimprove formation contact and may include a sonde-to-wired pipeinterface for top contact.

Upper Injection Electrode and Gaps

Like the lower current injection system, an upper injection system mayinclude a wired pipe gap sub and an upper injection sub. Upper wiredpipe gap sub may be connected to a wired pipe-to-sonde sub that convertswired pipe back to connections internal to the drill string. The wiredpipe-to-sonde sub may or may not be integrated into the upper injectionsub. The upper injection sub may include a stabilizer to reduce gapshorting and improve formation contact and may include a sonde-to-wiredpipe interface for top contact. Upper injection system may include awireline wet connect to enable injection power to be transmitted fromthe surface and to enable high-speed data transfer for multiple shots.

In some embodiments, the upper injection electrode may include a wetconnect male configured to receive a monoconductor wireline to be“stabbed in.” This allows the injection system to accept power from asurface source. The connection may be to either the upper injectionelectrode, the lower injection electrode, or both. A special realtimemode for direct communications to MWD controller may be enabled, withcommunication occurring either by lower section wired pipe or short hopelectromagnetic communications.

Gradient Magnetometer Unit

In some embodiments, a gradient magnetometer unit (GMU) may include aplurality of tri-axial high-sensitivity, low noise magnetometersdefining a cross-borehole plane. In some embodiments, the GMU mayinclude four tri-axial high-sensitivity, low noise magnetometers, withthree magnetometers being evenly spaced about the tool axis and defininga cross-borehole plane and a fourth magnetometer positioned on the toolaxis and spaced apart from the cross-borehole plane. The magnetometersmay have a 10-30 second sample time, including processing and filtering.In some embodiments, the magnetometer assembly is calibratable (possiblyas a sub, depending on magnetic content). In some embodiments, a BHA mayinclude two GMUs, with one GMU positioned above the MWD system and onebelow the MWD system.

In some embodiments, a connection between the BHA and an injection submay comprise a direct connect (part of BHA), a wired pipe connection, oran installed wireline connection. A connection between injectionelectrodes may comprise a wired pipe connection, or an installedwireline connection.

Injection/Generator Unit Surface Wireline Connection

In some embodiments, a system for nonaccess ARWD may include a steerablemotor and/or rotary steerable system. In certain embodiments, thedrilling assembly may include:

-   -   a) a plurality of collar-based magnetometers, which, in certain        embodiments may be radially displaced from the tool axis,    -   b) injection and return electrodes adapted to contact the        formation. In certain embodiments, the wiring or other current        paths may be within the BHA,    -   c) a current injection power supply integrated with the tool,        adapted to energize the electrodes to inject current into        formation,    -   d) a downhole computer adapted to carry out the processing and        data reduction, and    -   e) a communication system allowing commands and configuration to        be sent downhole and relay results to the surface.

FIG. 1 depicts three configurations of the current injection system. InFIG. 1 a , power is supplied at the surface and the excitation supplyelectrode is downhole with return electrode at the surface. The sensorsare the four dots next to the bit, and insulating gaps are shown. Incertain embodiments, the current runs through the entirety of thedrillstring. In 1 b, the power supply is downhole, with the supplyelectrode above the sensor and the return electrode further up the drillstring. This configuration does not require that the upper drillstringcarry injection current. In 1 c, the injection electrode is in the bit,the return electrode is above the bit such that the current endpointsstraddle the sensors.

In the configuration shown in FIG. 1 a , the drilling BHA approaches atarget borehole, and the sensors are near the bit. In certainembodiments, the sensors are triaxial fluxgate magnetometers that allowthe determination of distance and direction to the target well if acurrent can be placed on the target. The current on the target comesfrom the current injected into formation through the supply electrode.The power supply at surface delivers the current to the supply electrodealong the drillstring between surface and the electrode, using eitherwired pipe or a wireline deployed through the drillstring. The injectedcurrent may travel through formation and return to the return electrodeto complete the circuit with the power supply. As the target casing hasa higher conductivity than the surrounding formation, some current inthe neighborhood of the target will collect on the target to minimizethe current return path. This is the source of the signal that ismeasured by the magnetometers, allowing calculation of direction anddistance through the differing signal levels seen at magnetometers indiffering positions relative to the current on the target.

In FIG. 1 b , the excitation power supply is placed in the drillstring.This placement, coupled with excitation current electrodes in thedrillstring, does not require the majority of the drillstring to carry acurrent path for the excitation current. Separation between the twoelectrodes allows the current to travel through enough of the formationto not be short circuited directly back onto the drillstring. Insulatinggaps in the drillstring may define the electrode locations. Measurementof the magnetic signals and calculation of the distance and directionresults proceeds in the same way as 1 a.

In FIG. 1 c , the sensors are placed between the two electrodes. In 1 c,the downward flowing current in the target from the upper electrode andthe upward flowing current from the lower electrode will add, providinga larger current signal in the target.

In other embodiments, some sensors may be positioned above and belowmultiple electrode sections. The additional data from differentlocations may reduce measurement noise, cross validate results, andassist in tracking the target trajectory from a smaller number of shotlocations.

FIG. 1 depicts embodiments in which the ranging magnetometers are nearthe bit, allowing the target to be located and the drilling well to bepositioned near to the bottom of the hole. In certain embodiments, thelower portion of the drillstring may comprise magnetizable steel(including the bit), which may interact with the ranging measurements.In certain embodiments, sensors may be located higher in thedrillstring, such as above motors or other large ferromagneticcomponents. Such positioning may increase the quality of themeasurements at the cost of displacing the sensors in the trajectorydrilled.

The system may also incorporate insulation on the exterior of thedrillstring in between an electrode and the sensors. Insulation mayreduce current from short circuiting using the drillstring itself andavoid stray current on the tool body next to the sensors.

The energy source for the excitation power may be from batteries in thedrillstring, from a downhole hydraulic generator powered by the mudflow, or a hybrid system that stores energy from the generator for usein shots taken with the pumps off and the drillstring stable.

FIGS. 3A and 3B illustrate two embodiments of a drilling BHA 301suitable for use in the system of FIG. 1 a , in which power is suppliedat the surface, the excitation supply electrode is downhole, and thereturn electrode is at the surface. BHA 301 may be a gradient rangingBHA with surface connectivity. BHA 301 is shown on a drill string 119 inan open (uncased) borehole 100. BHA 301 may include a firstelectrically-insulating gap 101 in the drillstring 119, which serve toseparate the upper electrode from the lower portions of the BHA. BHA 301may include a second electrically insulating gap 102 in the drillstringto further isolate the upper electrode and lower electrodes. BHA 301 mayinclude a third electrically insulating gap 103 in thedrillstring—preventing or reducing injected current flow down along theBHA. BHA 301 may include a plurality of spacing collars 104, which maycomprise pipes of steel or nonmagnetic composition, these spacingcollars are to ensure the injection point is a sufficient distance abovegradient BHA components 106 and 109. Additionally, these collars orpipes may in some embodiments contain wiring or other communicationinfrastructure to allow bidirectional communications between the MWDsystem 107 and the injection current power supply and controller 115. Inother embodiments, there may be no communication between the MWD system107 and the injection power supply and controller 115 (in which case 115may operate autonomously). In some embodiments these may be wired orlined drill pipe or collars. In some embodiments collars 104 may have aninsulating coating on their outside to prevent injection currentaccumulation.

BHA 301 may further include a MWD bi-directional telemetry interface105, an optional first nonmagnetic BHA component 106, an MWD system 107,steerable component 108, an optional second nonmagnetic BHA component109, and a drill bit 110. BHA 301 may further include first and secondgradient magnetometer arrays 111 and 112, respectively, spacing drillcollars 104, a BHA ground-isolation gap 121, an upper ground isolationgap 120, an electrode housing/sub 122, and an electrode 125.

MWD bi-directional telemetry interface 105 may be configured to send andreceive data from the surface to and from the other BHA components(nonmagnetic BHA component 106, MWD system 107, steerable component 108,and optional second nonmagnetic BHA component 109). Interface 105 mayinclude electromagnetic, mud pulse, or acoustic telemetry, orcombinations thereof. Interface 105 could also include a telemetryinterface for sending data via modem via connected power/data conductor126.

Optional first nonmagnetic BHA component 106 houses first gradientmagnetometer array 111. BHA component 106 may have electrical orwireless connectivity with the interface 105, or other BHA components(as above). The placement of optional BHA component 106 in FIG. 3A isfor illustration only; the component 106 may be positioned anywherealong the length of BHA 301. Likewise, the other BHA components can bepositioned or combined as needed.

MWD System 107 may include magnetic and/or inertial sensors, includingwithout limitation magnetometers, accelerometers, gyroscopes, and mayalso include additional sensors as desired for well drilling.

Optional second nonmagnetic BHA component 109 houses a second gradientmagnetometer array 112. Optional BHA component 109 may have electricalor wireless connectivity with the interface 105 or other BHA components(as above). Embodiments of BHA 301 may include one or both of first andsecond nonmagnetic BHA components 106, 109.

Gradient magnetometer arrays 111, 112 may each comprise three or morecross-axis coplanar tri-axial magnetometer packages, with at least threebeing spaced as far from the BHA axis as possible.

In the embodiment shown in FIG. 3 a , the BHA further includes anelectrode power/data interconnect 124 and a power/data conductor 126.Conductor 126 may be installed/integral with the BHA, or may be on awireline that is run in and connected and disconnected periodically, ora combination of both. Power/Data conductor 126 may be wireline run indrillpipe, wired pipe, or conductor-lined pipe. Conductor 126 may beintegral and fixed to the pipe or freely run through the pipe andremovable.

Spacing drill collars 123 may include wiring to enable telemetryinterface 105 to connect to power/data conductor 126 for the purpose ofbi-directional communications to surface. BHA Ground-isolation gap 121prevents current flow along BHA 301 to and from electrode 125. Upperground isolation gap 120 prevents current flow along drillstring 119 toand from electrode 125. Electrode power/data interconnect 124 allows awired connection to surface for power delivery to electrode andoptionally bidirectional communications. Interconnect 124 may include aconnection to the telemetry interface 105 via optional spacing collars123.

Electrode 125 is configured to injecting ranging current into theformation surrounding borehole 100. The current flow into formation fromelectrode 125 in contact with borehole 100 and/or via drilling fluid inthe annular space between BHA and borehole is indicated in FIG. 3A bylines 127.

FIG. 3B illustrates another embodiment of a drilling BHA 301 suitablefor use in the system of FIG. 1 a . While many of the elements are thesame, in FIG. 3B BHA 301 includes a lower injection electrode contact113, a lower injection electrode housing/sub 114, and an injectioncurrent power supply and controller 115. In some embodiments, thisdevice may be autonomous, while in other embodiments it may operate inresponse to commands from a connected MWD. In some embodiments, this mayinclude power generation and storage, and in some embodiments this mayinclude one or more batteries. BHA 301 may also include an upperelectrode interconnecting conductor 116. Without limitation, in someembodiments, conductor 116 may be a wireline installed through collarsor pipes, and in other embodiments this may be an integrated conductorin wired or conductor-lined drill pipe. BHA 301 may also include anupper injection electrode contact 117, an upper injection electrodehousing/sub 118, which may in some embodiments contain interfaces toconnector 116 via wireline, wired or lined drill pipe, and a drill pipeto surface 119, which may in some embodiments contain additionalelectrically insulating gap subs.

Electrode 125 is configured to injecting ranging current into theformation surrounding borehole 100. The current flow into formation fromelectrode 125 in contact with borehole 100 and/or via drilling fluid inthe annular space between BHA and borehole is indicated in FIG. 3B bylines 127.

In an alternative embodiment, two boreholes may be drilled at the sametime from separate rigs. In the embodiment shown in FIG. 2 and describedbelow, two wells are oriented in the same general direction and may besubstantially parallel. In the embodiment shown in FIG. 6 , two wellsare oriented generally in opposite directions and may be substantiallyparallel. The configurations shown in FIGS. 2 and 6 are merelyillustrative. The boreholes can both exist at any relative trajectory,and need not be horizontal.

In some embodiments, an alternative ARWD system may include, forexample, a magnetometer mounted in a BHA, a magnetic field sourcecomprising a rotating permanent magnet, and an MWD controller. Thesecomponents may be included on or form part of the BHA.

Referring now to FIG. 2 , an exemplary two-hole system may beimplemented at the earth's surface 31, with wells extending into thesubsurface 30. The first drilling assembly includes a first rig 10 and afirst drill string 13 operating in a first borehole 15. First drillstring 13 may comprise jointed pipes, coiled tubing, etc. First borehole15 may or may not include steel or nonmagnetic casing installed in someportions thereof. The lower end of first drill string 13 may include afirst bottomhole assembly (BHA) 201 that includes a first boreholebi-directional telemetry interface 17, a first MWD system 19, a firststeerable component 23, a first drill bit 21, and a first nonmagneticBHA component 27. First BHA 201 defines a first borehole axis 33.

First telemetry interface 17 may be a bi-directional interfaceconfigured to send and receive data to/from the surface. Examples ofsuitable telemetry techniques include but are not limited toelectromagnetic telemetry, mud pulse telemetry, acoustic telemetry, andcombinations of multiple telemetry techniques.

First MWD system 19 may be used to collect navigation data in firstborehole 15. First MWD system 19 may include magnetic and/or inertialsensors, including without limitation multiple precision calibratedmagnetometers, accelerometers, and gyroscopes, and combinations thereof.The sensors may be DC and/or AC measuring, and may include filtering orprocessing to improve accuracy in static and/or dynamic conditions.

First steerable component 23 may be a rotary steerable system, benthousing drilling motor, turbine, directional hammer, or any othersteerable component.

Nonmagnetic BHA component 27 may include a magnetic field sourcecomprising one or more permanent transverse (cross axis) magnets 207(shown in FIGS. 4C, 4D) having a north-south axis perpendicular to theborehole axis 33, so as to create an elliptically polarized magneticfield 29 during rotation of BHA 201 about axis 33. Magnetic field 29appears as an alternating magnetic field at points away from BHA 201.

Still referring to FIG. 2 , the second drilling assembly includes asecond rig 12 and a second drill string 14 operating in a secondborehole 16. Second drill string 14 may comprise jointed pipes, coiledtubing, etc. Second borehole 16 may or may not have steel or nonmagneticcasing installed in some portions thereof. The lower end of second drillstring 14 may include a second BHA 202 comprising a secondbi-directional telemetry interface 18, a second MWD system 20, a secondsteerable component 24, a second drill bit 22, and at least one two- orthree-axis magnetic field sensor 28. Second BHA 202 defines a secondborehole axis 34.

Like first telemetry interface 17, second telemetry interface 18 may beconfigured to send and receive data to/from the surface and may make useof electromagnetic telemetry, mud pulse telemetry, acoustic telemetry,and combinations of multiple telemetry techniques.

Second MWD system 20 may be used to collect navigation data in secondborehole 16. Second MWD system 20 may include magnetic and/or inertialsensors, including without limitation multiple precision calibratedmagnetometers, accelerometers, and/or gyroscopes, and combinationsthereof. Sensors may be DC and/or AC measuring, and may includefiltering or processing to improve accuracy in static and/or dynamicconditions.

Magnetic field sensor 28 may have at least two axes orthogonal to axis34 and may include sensors mounted so as to enable determination oftheir direction with respect to second MWD system 20. Data from thissensor may be processed in a downhole computer and results and/or rawdata may be sent to surface via second telemetry interface 18. Thedownhole computer may also use data gathered by the MWD system 20, ordata received from surface control system/center (32) via the telemetryinterface 18. In this embodiment, single magnetometer is sufficient, butmore can be used. Each magnetometer may be built into the wall of a BHAor provided in a sonde or cartridge mounted inside the BHA. As set outbelow in more detail, the first drilling assembly may also include oneor more magnetic field sensors 28.

Like first steerable component 23, second steerable component 24 may bea rotary steerable system, bent housing drilling motor, turbine,directional hammer, or any other steerable component.

The system shown in FIG. 2 further includes a control system 32 locatedat the surface. Control system 32 may be configured to receivesensor-generated raw data and computed readings and results, which maybe sent or used in drilling either borehole 15, 16. Control system 32may further be configured to send data downhole to either MWD system 19,20. The system may further include a bi-directional data link 25 betweenfirst rig 10 and control system 32 and a bi-directional data link 26between second rig 12 and control system 32. The system may also includeone or more surface transceivers, each located at or near a drilling rigand configured to engage a downhole telemetry interface, as well asadditional sensors, power supplies, surface electrodes and/or rigcontrols, all of which may be connected to a surface computer.

FIGS. 4A-4B illustrate embodiments of BHAs that can be used as secondBHA 202 in the systems illustrated in FIG. 2 . FIGS. 4C-4D illustrateembodiments of BHAs that can be used as first BHA 201 illustrated inFIG. 2 . In the embodiments shown in FIGS. 4A and 4C, second steerablecomponent 24 is a rotary steerable 41. In the embodiments shown in FIGS.4B and 4D, second steerable component 24 is a bent housing drillingmotor 42. As noted above, other steerable components may be used.

In each embodiment, the BHA 201, 202 may include a downhole computer 40(FIGS. 4A-D), which may be connected to all BHA sensors and can beprogrammed to collect data and compute results from magnetic fieldsensor(s) 28 as well as from standard MWD navigation sensors(magnetometers, accelerometers, and/or gyroscopes) and other sensors inthe BHA. Downhole computer 40 may be configured to transmit and receivedata from second telemetry interface 18.

In the embodiments shown in FIGS. 4C and 4D, BHA 201 also includes atleast one optional magnetic field sensor 28. This optional placement ofmagnetic field sensors 28 on BHA 201 enables BHA 201 to be used as botha ranging source and ranging sensing device, as shown in FIG. 6 .

As set out above with respect to FIG. 2 , first BHA 201 may include anonmagnetic BHA component that supports one or more permanent transverse(cross axis) magnets 207 having a north-south axis perpendicular to theborehole axis. As depicted in FIG. 4C, nonmagnetic BHA component 44 maybe an extension to a rotary steerable or may be integrated with therotating portion of a rotary steerable. This component may or may not bea separate piece from the rotary steerable itself.

Alternatively, as depicted in FIG. 4D, nonmagnetic BHA component 45 maybe an extension to a positive displacement mud motor with bent housing42 or integrated with the mandrel of this motor, which reduces length.This component may or may not be a separate piece from the motor itself.

As shown in FIG. 5 , either BHA or both BHAs may include a second magnetsub 51 including permanent magnets 52. Generally, second magnet sub 51can go anywhere, but in some embodiments it may be above and spacedapart from sensors 28 and 61. In some embodiments second magnet sub 51may be at least 10 feet, at least 20 feet, or at least 30 feet abovesensors 28. Second magnet sub 51 creates a second elliptically polarizedmagnetic field 63 during rotation of BHA 201. Magnetic field 63 appearsas an alternating magnetic field at points away from second magnet sub51. If the BHA includes a mud motor between nonmagnetic BHA component 45or 44 and second magnet sub 51, the elliptically polarized magneticfields created by each sub will appear as overlapping alternatingmagnetic fields with different frequencies at points away from therespective BHAs.

Referring now to FIG. 6 , the concepts described herein can be appliedin a system in which two wells are drilled within ranging distance ofeach other. Each well may be drilled with a drilling assembly thatincludes at least two magnetic field sources and at least one rangingmagnetometer, among the other items mentioned herein. In thisembodiment, multiple ranging measurements can be made between the twodrillstrings. These measurements may be combined with averaging or datafitting techniques including wellbore survey information, or machinelearning methods. As illustrated, each magnetic field source maycomprise a rotating permanent magnet and each ranging magnetometercollects ranging data from a location behind the bit.

In a system in which a rotating magnet is positioned at a singlelocation and measurements are made with a single triaxial magnetometer,distance and direction are calculated based on the field measured at themagnetometer using differential gradiometry or source strengthcalibrated at surface or via downhole measurements at multiple locations(station-based or with a sweep of the drillstring). However, the qualityof the source strength estimate may be compromised by localferromagnetic components in the BHA. In contrast, if multiple sensorsspaced apart in the sensing BHA, either radially or longitudinally, or asingle radially displaced sensor carouseled or rotated with the BHA,signals from all of the sensors can be used in the calculation. Usingdata from multiple sensors may be advantageous in cancelling errors dueto BHA effect, and may improve results from ranging inside casing,especially during twinning or interception.

In wireline-based systems, the magnetic field and other sensor data maybe communicated to the surface and processed there. In this embodiment,the data may optionally be processed downhole in the tool package. Dataprocessing may include:

-   -   A) after a layer of filtering, the magnetic field signals from        the various magnetometer axes (3 axes per magnetometer, N        magnetometers at multiple locations) are coherently measured.        The in phase and out of phase components may be assessed        separately: nominally, all signal power on all axes should be in        phase together with each other and the excitation source, so out        of phase signal is an error source that can serve as a        qualifier.    -   B) The average field may be computed, allowing an overall signal        strength to be computed, and the direction from sensor to        target. From the average, the deltas of each individual        magnetometer may be computed, showing how the signal varies in        strength and direction from the central average. These deltas        allow computation of the distance as a gradient of the magnetic        field. The distance can be corrected if desired using the        direction as the field direction and the field gradient should        have a certain relation if the field source is a current on a        nearby linear target. Deviations from this relationship can be        used as an additional qualifier.

Certain magnetometer placement locations may improve the accuracy of thecalculated results. High radial displacement may allow for maximaldeltas for gradient measurements of distance.

When results are computed downhole, communication may be used forreporting results and monitoring, and for command and configuration tobe sent downhole. The communications may be accomplished with mud pulseor electromagnetic signal propagation, or wired pipe with a wet connectwireline deployed from surface. Additionally commands can becommunicated mechanically, for example by setting a shot to be takenfollowing a delay after pumps and rotation stop.

The system may be configured to use active signal alone, passive signalalone, or a combination of the two. In certain embodiments, this systemallows the communication of bit depth from surface to tool, so that thisinformation is available to the calculation algorithm.

This system may incorporate a gyroscopic heading determination, allowingazimuth and toolface to be determined relative to the Earth's rotationrather than the magnetic field alone.

In certain embodiments, the ranging results are available downholeallowing the directional control of the steerable component to becommanded to follow a preplanned wellpath with respect to the targetwell. This closed loop control system may be based on the activeresults, passive results, or a combination of each. Bit depthinformation may be communicated down from surface for use in rangingcalculations and drilling parameters such as dogleg achieved. Machinelearning techniques may be used to accommodate changes in formationdrilling characteristics, smooth ranging noise, and achieve desiredintercept objectives. Different modes and parameters can be set bycommands from surface, and continuous monitoring of the ranging anddrilling results can be sent up for human reporting.

We claim:
 1. A system for drilling first and second boreholes in aformation, the system comprising: a first drilling assembly in the firstborehole, the first drilling assembly including a first drill string, afirst drill bit and a first bottomhole assembly (BHA) connected to thefirst drill bit, the first BHA including a firstmeasurement-while-drilling (MWD) system, a first bi-directional MWDtelemetry interface, a first steering component, and a first magneticfield source comprising at first permanent magnet having a north-southaxis perpendicular to the longitudinal axis of the first BHA, so as tocreate an elliptically polarized magnetic field during longitudinalrotation of the first BHA; a second drilling assembly in the secondborehole, the second drilling assembly including a second drill string,a second drill bit and a second BHA connected to the second drill bit,the second BHA including a second MWD system, a second bi-directionalMWD telemetry interface, a second steering component, and at least oneranging magnetometer incorporated into the BHA, wherein the at least oneranging magnetometer is configured to collect ranging measurements ofthe elliptically polarized magnetic field generated in the firstdrilling assembly from a location behind the second drill bit, a secondpermanent magnet, the second permanent magnet positioned within thefirst or second drilling assembly; and wherein at least one of the firstand second BHAs includes a third permanent magnet having a north-southaxis perpendicular to the longitudinal axis of the first BHA, andwherein the third permanent magnet is above and spaced apart along theat least one BHA from the first or second permanent magnet,respectively.
 2. A system for drilling first and second boreholes in aformation, the system comprising: a first drilling assembly in the firstborehole, the first drilling assembly including a first drill string, afirst drill bit, and a first bottomhole assembly (BHA) connected to thefirst drill bit, the first BHA including a firstmeasurement-while-drilling (MWD) system, a first bi-directional MWDtelemetry interface, a first steering component, and a first magneticfield source comprising at least one permanent magnet having anorth-south axis perpendicular to the longitudinal axis of the firstBHA, so as to create an elliptically polarized magnetic field duringlongitudinal rotation of the first BHA; and a second drilling assemblyin the second borehole, the second drilling assembly including a seconddrilling string, a second drill bit and a second BHA connected to thesecond drill bit, the second BHA including a second MWD system, a secondbi-directional MWD telemetry interface, a second steering component, andat least one ranging magnetometer incorporated in the BHA, wherein theat least one ranging magnetometer is configured to collect rangingmeasurements of the elliptically polarized magnetic field generated inthe first drilling assembly from a location behind the second drill bit;a second permanent magnet, the second permanent magnet positioned withinthe first or second drilling assembly, and wherein the first BHA furtherincludes a third permanent magnet having a north-south axisperpendicular to the longitudinal axis of the first BHA and wherein thesecond BHA further includes a fourth permanent magnet having anorth-south axis perpendicular to the longitudinal axis of the secondBHA, and wherein the third and fourth permanent magnets are above andspaced apart along the respective BHA from the first and secondpermanent magnets, respectively.
 3. A method for drilling first andsecond boreholes, comprising: a) providing a system for drilling firstand second boreholes in a formation, the system comprising: a firstdrilling assembly in the first borehole, the first drilling assemblyincluding a first drill string, a first drill bit and a first bottomholeassembly (BHA) connected to the first drill bit, the first BHA includinga first measurement-while-drilling (MWD) system, a first bi-directionalMWD telemetry interface, a first steerable component, and a firstmagnetic field source comprising at least one permanent magnet having anorth-south axis perpendicular to the longitudinal axis of the firstBHA, so as to create an elliptically polarized magnetic field duringlongitudinal rotation of the first BHA; a second drilling assembly inthe second borehole, the second drilling assembly including a seconddrill string, a second drill bit and a second BHA connected to thesecond drill bit, the second BHA including a second MWD system, a secondbi-directional MWD telemetry interface, a second steerable component,and at least one ranging magnetometer incorporated into the second BHA,wherein the at least one ranging magnetometer is configured to collectranging measurements from behind the second drill bit; a secondpermanent magnet, the second permanent magnet positioned within thefirst or second drilling assembly; and wherein at least one of the firstand second BHAs includes a third permanent magnet having a north-southaxis perpendicular to the longitudinal axis of the first BHA, andwherein the third permanent magnet is above and spaced apart along theat least one BHA from the first or second permanent magnet,respectively; b) during rotation of the first BHA, generating a magneticfield using the first magnetic field source; c) using the at least oneranging magnetometer in the second borehole to measure the magneticfield created in step b); and d) using the measurements made in step c)to steer at least one of the first and second drilling assemblies. 4.The method of claim 3 wherein the first and second drilling assembliesare both rotating during step b).
 5. The method of claim 4, furtherrepeating steps b)-d) without surface intervention.
 6. The method ofclaim 4 wherein step d) includes making steering decisions based onactive data alone, passive data, or a combination of active and passivedata.
 7. The method of claim 3 wherein the magnetic field sourcecomprises at least one permanent magnet having a north-south axisperpendicular to the longitudinal axis of the first BHA, so as to createan elliptically polarized magnetic field during longitudinal rotation ofthe first BHA.
 8. The method of claim 3 wherein step c) is carried outwithout tripping out the first or second drillstring or requiringwireline access to the first or second borehole.
 9. The method of claim3 wherein the magnetic field source comprises one or more permanenttransverse magnets having a north-south axis perpendicular to the axisof the first borehole so as to create an elliptically polarizedalternating magnetic field during rotation of the first BHA, wherein theranging magnetometer has at least two axes orthogonal to the axis of thesecond borehole, and wherein the ranging magnetometer includes sensorsmounted so as to enable determination of their direction with respect tothe second MWD system.
 10. The method of claim 3 wherein the magneticfield source comprises a current injected into formation.
 11. The methodof claim 10 wherein the first drilling assembly further includes anelectrode for injecting current into the formation, and wherein power issupplied to the electrodes via an insulated current path that isintegral with the drillstring.
 12. The method of claim 3 wherein step d)includes measuring a passive magnetic signature of a ferromagnetictarget and computing a distance and direction to the target.
 13. Themethod of claim 3, further including a step of communicating a bit depthdownhole from surface and using the bit depth in step d).
 14. The methodof claim 3 wherein step d) includes making distance and directioncalculations downhole.
 15. The method of claim 3, further including astep of communicating measurement data to the surface.
 16. The method ofclaim 3, further including a step of communicating raw data to thesurface.
 17. The method of claim 3 wherein the first and second drillingassemblies each include at least two magnetic field sources and at leastone ranging magnetometer.
 18. The method of claim 3 wherein step d)includes combining measurements made in step c) with averaging or datafitting techniques including wellbore survey information, or withmachine learning methods.